This PDF file contains the front matter associated with SPIE Proceedings Volume 10370, including the Title Page, Copyright information, Table of Contents, Introduction (if any), and Conference Committee listing.

The need for faster PV qualification tests that more accurately match field observations is leading to tests with higher acceleration levels, and validating the new tests through comparison to field data is an important step. We have tested and compared a wide panel of backsheets according to a proposed new backsheet UV exposure qualification standard from the International Electrotechnical Commission (IEC). Weathering Technical Standard IEC 62788-7-2 specifies higher irradiance and higher black panel temperature UV Xenon exposures. We tested PVF, PVDF, PET, PA and FEVEbased backsheets in glass laminates and simple backsheet coupons in UV exposure condition A3 (0.8W/sqmnm@340nm and 90° C BPT) We find mild yellowing with no mechanical loss in the original lower intensity ASTM G155 0.55 W/sqm-nm 70C BPT exposure condition. The new A3 exposures creates mechanical loss in sensitive backsheets, with no effect on known durable backsheets. Results from the new exposure are closer to field mechanical loss data.

The selection of polymeric materials utilized in photovoltaic (PV) modules has changed relatively little since the inception of the PV industry, with ethylene-vinyl acetate (EVA), polyethylene terephthalate (PET), and fluoropolymer-based laminates being the most widely adopted primary components of the encapsulant and backsheet materials. The backsheet must serve to electrically insulate the solar cells and protect them from the effects of weathering. Due to continued downward pressure on cost, other polymeric materials are being formulated to withstand outdoor exposure for use in backsheets to replace either the PET film, the fluoropoymer film, or both. Because of their relatively recent deployment, less is known about their reliability and if they are durable enough to fulfill the ≥25 year warranties of current PV modules. This work presents a degradation analysis of field-exposed modules with polyamide- and polyester-based backsheets. Modules were exposed for up to five years in different geographic locations: USA (Maryland, Ohio), China, and Italy. Surface and cross-sectional analysis included visual inspection, colorimetry, glossimetry, and Fourier-transform infrared spectroscopy. Each module experienced different types of degradation depending on the exposure site, even for the same material and module brand. For instance, the polyamide-based backsheet experienced hairline cracking and greater yellowing and chemical changes in China (Changsu, humid subtropical climate), while in Italy (Rome, hot-summer Mediterranean climate) it underwent macroscopic cracking and greater losses in gloss. Spectroscopic studies have permitted identification of degradation products and changes in polymer structure over time. Comparisons are made to fielded modules with fluoropolymer-based backsheets, as well as backsheet materials in accelerated laboratory exposures. Implications for qualification testing and service life prediction of the non-fluoropolymer-based backsheets are discussed.

Long term outdoor durability of photovoltaic (PV) module backsheets is critical to a module's power output over its lifetime. The use of uoropolymer-based backsheets or the addition of stabilizers to polyethylene-terephthalate (PET) and polyamide (PA) type backsheets can help extend their lifetime. This study presents the performance of 21 backsheets made of 8 different material combinations under ASTM G154 Cycle 4 accelerated light exposures. The backsheets were subjected to 4000 hours of high irradiance UVA light at a peak intensity of 1.55 W=m² at 340 nm at 70°C with and without a condensing humidity cycle at 50°C. Backsheets were evaluated, with repeated measurements, using various evaluation techniques to identify and assess potential signs of degradation. These evaluations included the yellowness index (YI), CIE color space coordinates, and gloss at 20, 60, and 85°. The temporal evolution of the relative color change ΔE was statistically analyzed to develop a stress-response model which used the UVA light dose to predict color change. It was found that the PVF/PET/E backsheet performed the best while PET/PET/E and THV/PET/EVA backsheets performed the worst. Additionally, substantial variation in color change response, attributable to key manufacturing differences, was observed within a given material type.

Poly(ethylene-terephthalate) (PET) film is widely used in photovoltaic module backsheets for its dielectric break- down strength, and in applications requiring high optical clarity for its high transmission in the visible region. However, PET degrades and loses optical clarity under exposure to ultraviolet (UV) irradiance, heat, and moisture. Stabilizers are often included in PET formulation to increase its longevity; however, even these are subject to degradation and further reduce optical clarity. To study the weathering induced changes in the optical properties in PET films, samples of a UV-stabilized grade of PET were exposed to heat, moisture, and UV irradiance as prescribed by ASTM-G154 Cycle 4 for 168 hour time intervals. UV-Vis reflection and transmission spectra were collected via Multi-Angle, Polarization-Dependent, Reflection, Transmission, and Scattering (MaPd:RTS) spectroscopy after each exposure interval. The resulting spectra were used to calculate the complex index of refraction throughout the UV-Vis spectral region via an iterative optimization process based upon the Fresnel equations. The index of refraction and extinction coefficient were found to vary throughout the UV-Vis region with time under exposure. The spectra were also used to investigate changes in light scattering behavior with increasing exposure time. The intensity of scattered light was found to increase at higher angles with time under exposure.

Quantification of the effect of temperature on photovoltaic (PV) module efficiency is vital to the correct interpretation of PV module performance under varied environmental conditions. However, previous work has demonstrated that PV module arrays in the field are subject to significant location-based temperature variations associated with, for example, local heating/cooling and array edge effects. Such thermal non-uniformity can potentially lead to under-prediction or over-prediction of PV array performance due to an incorrect interpretation of individual module temperature de-rating. In the current work, a simulated method for modeling the thermal profile of an extended PV array has been investigated through extensive computational modeling utilizing ANSYS, a high-performance computational fluid dynamics (CFD) software tool. Using the local wind speed as an input, simulations were run to determine the velocity at particular points along modular strings corresponding to the locations of temperature sensors along strings in the field. The point velocities were utilized along with laminar flow theories in order to calculate Nusselt’s number for each point. These calculations produced a heat flux profile which, when combined with local thermal and solar radiation profiles, were used as inputs in an ANSYS Thermal Transient model that generated a solar string operating temperature profile. A comparison of the data collected during field testing, and the data fabricated by ANSYS simulations, will be discussed in order to authenticate the accuracy of the model.

The determinations of performance ratio (per IEC 61724 standard) and degradation rate (using slope of performance ratio over time) of photovoltaic (PV) modules in a power plant are computed based on the power (Pmax) temperature coefficient (TC) data of the unexposed modules or the exposed modules during the commissioning time of the plant. The temperature coefficient of Pmax is typically assumed to not change over the lifetime of the module in the field. Therefore, this study was carried out in an attempt to investigate the validity of this assumption and current practice. Several 18-19 years old field aged modules from four different manufacturers were tested for the baseline light I-V measurements and dark I-V measurements to determine the power temperature coefficient and series resistance for each module. Using the dark I-V and light I-V data, the series resistances (Rs) and shunt resistances (Rsh) were calculated in order to determine their impact on fill factor (FF) and hence on Pmax. The result of this work indicates a measurable drop in fill factor (FF) as the series resistance (Rs) increased which in turn increases the temperature coefficient of Pmax. This determination goes against the typical assumption that the temperature coefficient of (Pmax) for aged modules does not change over time. The outcome of this work has a significant implication on the performance ratio and degradation rate determinations based on the temperature coefficient of Pmax of new modules which is not an accurate practice for analyzing field aged modules.

Unpackaged CIGS solar cells were simultaneously exposed to illumination and either dry heat, damp heat or dry cold followed by thermal cycling. In-situ monitoring of their electrical parameters demonstrated a rapid decrease of the efficiency for the solar cells exposed to damp heat plus illumination. This decrease was mainly driven by changes in the shunt resistances, affecting also the open circuit voltage and the fill factor, while a minor increase in series resistance was also observed. All solar cells exposed to dry heat plus illumination were quite stable during the exposure in both their electrical and material parameters. The dry cold/cycling solar cells similarly barely showed any degradation, although one sample became shunted, likely due to structural changes in the solar cell. From these experiments, it was concluded that unpackaged CIGS solar cells can degrade rapidly in the presence of humidity, but in the absence of water, these solar cells were mostly stable. This indicates that these unpackaged CIGS solar cells can majorly stand combined illumination, and the accompanying electrical field, and various temperatures.

Rechargeable lithium-ion batteries with liquid electrolytes are the main energy source for many electronic devices that we use in our everyday lives. However, one of the main drawbacks of this energy storage technology is the use of liquid electrolyte, which can be hazardous to the user as well as the environment. Moreover, lithium-ion batteries are limited in voltage, energy density and operating temperature range. One of the most novel and promising battery technologies available to overcome the above-mentioned drawbacks is the Solid-State Lithium-Ion Battery (SSLB). This battery type can be produced without limitations to the geometry and is also bendable, which is not possible with conventional batteries¹ . Additionally, SSLBs are characterized by high volumetric and gravimetric energy density and are intrinsically safe since no liquid electrolyte is used^2-4. Nevertheless, the manufacturing costs of these batteries are still high. The existing production-technologies are comparable to the processes used in the semiconductor industry and single cells are produced in batches with masked-deposition at low deposition rates. In order to decrease manufacturing costs and to move towards continuous production, Roll2Roll production methods are being proposed^{5, 6}. These methods offer the possibility of producing large quantities of substrates with deposited SSLB-layers. From this coated substrate, single cells can be cut out. For the flexible decollation of SSLB-cells from the substrate, new manufacturing technologies have to be developed since blade-cutting, punching or conventional laser-cutting processes lead to short circuiting between the layers. Here, ultra-short pulsed laser ablation and cutting allows the flexible decollation of SSLBs. Through selective ablation of individual layers, an area for the cutting kerf is prepared to ensure a shortcut-free decollation.

Potential induced degradation (PID) causes severe damage and financial losses even in modern PV-installations. In Germany, approximately 19% of PV-installations suffer from PID and resulting power loss. This paper focuses on the impact of PID in real installations and how different evaluated time intervals influence the performance ratio (PR) and the determined degradation rate. The analysis focuses exemplarily on a 314 kWp PV-system in the Atlantic coastal climate. IR-imaging is used for identifying PID without operation interruption. Historic electric performance data are available from a monitoring system for several years on system level, string level as well as punctually measured module string IV- curves. The data sets are combined for understanding the PID behavior of this PV plant. The number of PID affected cells within a string varies strongly between 1 to 22% with the string position on the building complex. With increasing number of PID-affected cells the performance ratio decreases down to 60% for daily and monthly periods. Local differences in PID evolution rates are identified. An average PR-reduction of -3.65% per year is found for the PV-plant. On the string level the degradation rate varied up to 8.8% per year depending on the string position and the time period. The analysis reveals that PID generation and evolution in roof-top installations on industrial buildings with locally varying operation conditions can be fairly complex. The results yield that local operating conditions, e.g. ambient weather conditions as well as surrounding conditions on an industrial building, seem to have a dominating impact on the PID evolution rate.

We have conducted potential induced degradation (PID) tests on CIGS photovoltaic (PV) modules with/without LED white light irradiation. Suppression of PID degradation was observed by light irradiation.

Potential-induced degradation (PID) is known to have a very severe effect on the reliability of PV modules. PID is caused due to the leakage of current from the cell circuit to the grounded frame under humid conditions of high voltage photovoltaic (PV) systems. There are multiple paths for the current leakage. The most dominant leakage path is from the cell to the frame through encapsulant, glass bulk and glass surface. This dominant path can be prevented by interrupting the electrical conductivity at the glass surface. In our previous works related to this topic, we demonstrated the effectiveness of glass surface conductivity interruption technique using one-cell PV coupons. In this work, we demonstrate the effectiveness of this technique using a full size commercial module susceptible to PID. The interruption of surface conductivity of the commercial module was achieved by attaching a narrow, thin flexible glass strips, from Corning, called Willow Glass on the glass surface along the inner edges of the frame. The flexible glass strip was attached to the module glass surface by heating the glass strip with an ionomer adhesive underneath using a handheld heat gun. The PID stress test was performed at 60°C and 85% RH for 96 hours at −600 V. Pre- and post-PID characterizations including I-V and electroluminescence were carried out to determine the performance loss and affected cell areas. This work demonstrates that the PID issue can be effectively addressed by using this current interruption technique. An important benefit of this approach is that this interruption technique can be applied after manufacturing the modules and after installing the modules in the field as well.

The Tucson Electric Power (TEP)/University of Arizona AzRISE (Arizona Research Institute for Solar Energy) solar test yard is continuing efforts to improve standardization and data acquisition reliability throughout the facility. Data reliability is ensured through temperature-insensitive data acquisition devices with battery backups in the upgraded test yard. Software improvements allow for real-time analysis of collected data, while uploading to a web server. Sample data illustrates high fidelity monitoring of the burn-in period of a polycrystalline silicon photovoltaic module test string with no data failures over 365 days of data collection. In addition to improved DAQ systems, precision temperature monitoring has been implemented so that PV module backside temperatures are routinely obtained. Weather station data acquired at the test yard provides local ambient temperature, humidity, wind speed, and irradiance measurements that have been utilized to enable characterization of PV module performance over an extended test period

Cracked PV-modules are frequently detected in PV-systems. The impact of cracked cells on the energy yield and module performance under real operating conditions is not yet understood but of great relevance. Standard tests cannot reveal the relevant information conclusively. Therefore, we conducted a twofold analysis. 1) field exposure (global analysis on string level as well as detailed analysis on module level), and 2) load testing in the lab. Here, we present comparative electroluminescence (EL-) images recorded in an outdoor test stand and during load testing. Additionally, infrared (IR-) images as well as power data obtained from loaded and operating (field) conditions are discussed.

The objective of this study is the numerical simulation of wind flow over solar photovoltaic panels. Nowadays there are 132 schools in Florida using solar energy in their buildings. Due to strong winds and hurricanes in that region is needed to determine the aerodynamic efforts from the flow of wind on photovoltaic panels to design with efficiency protectors and supporters to protect the panels. Thus this work proposes a 2D numerical simulation in steady state through the medium of Reynolds Averaged Navier Stokes (RANS) equations. The turbulence closure model used is the SST k-w.

Thin-film solar cells normally have the shortest energy payback time due to their simpler mass-production process compared to polycrystalline-Si photovoltaic (PV) modules, despite the fact that crystalline-Si-based technology typically has a longer total lifetime and a higher initial power conversion efficiency. For both types of modules, significant aging occurs during the first two years of usage with slower long-term aging over the module lifetime. The PV lifetime and the return-on-investment for local PV system installations rely on long-term device performance. Understanding the efficiency degradation behavior under a given set of environmental conditions is, therefore, a primary goal for experimental research and economic analysis. In the present work, in-situ measurements of key electrical characteristics (J, V, P_max, etc.) in polycrystalline-Si and CdTe thin-film PV modules have been analyzed. The modules were subjected to identical environmental conditions, representative of southern Arizona, in a full-scale, industrial-standard, environmental degradation chamber, equipped with a single-sun irradiance source, temperature, and humidity controls, and operating an accelerated lifecycle test (ALT) sequence. Initial results highlight differences in module performance with environmental conditions, including temperature de-rating effects, for the two technologies. Notably, the thin-film CdTe PV module was shown to be approximately 15% less sensitive to ambient temperature variation. After exposure to a seven-month equivalent compressed night-day weather cycling regimen the efficiency degradation rates of both PV technology types were obtained and will be discussed.

Electroluminescence imaging can be used as a non-invasive method to spatially assess performance degradation in photovoltaic (PV) modules. Cells, or regions of cells, that do not produce an infra-red luminescence signal under electrical excitation indicate potential damage in the module. In this study, an Andor iKon-M camera and an image acquisition tool provided by Andor have been utilized to obtain electroluminescent images of a full-sized multicrystalline PV module at regular intervals throughout an accelerated lifecycle test (ALC) performed in a large-scale environmental degradation chamber. Computer aided digital image analysis methods were then used to automate degradation assessment in the modules. Initial preprocessing of the images was designed to remove both background noise and barrel distortion in the image data. Image areas were then mapped so that changes in luminescent intensity across both individual cells and the full module could be identified. Two primary techniques for image analysis were subsequently investigated. In the first case, pixel intensity distributions were evaluated over each individual PV cell and changes to the intensities of the cells over the course of an ALC test were evaluated. In the second approach, intensity line scans of each of the cells in a PV module were performed and variations in line scan data were identified during the module ALC test. In this report, both the image acquisition and preprocessing technique and the contribution of each image analysis approach to an assessment of degradation behavior will be discussed.

Performance of a photovoltaic (PV) module is related to the micro-environment around the module. The position of photovoltaic modules in an array row have a large effect on the yellowing and gloss of PV module backsheet exposed in Dfa climatic zone (Gaithersburg, MD) with a polyethylene naphthalate (PEN) outer layer. <Stress/ Response< models of yellowing and gloss-losing as function of location parameters of module, including the shed, row, measurement position in a same module and the distance of module location to the row center, are under development. The module installation height had the greatest influence on degradation of PEN PV backsheet in the Dfa climatic zone. The module backsheets at the end of an array have higher degradation rate (edge effect). The edge effect decreases with increasing of module installation heights.